The present invention relates to methods for treating subterranean formations. More particularly, the present invention relates to methods of using viscosified treatment fluids that comprise a single salt aqueous fluid having a density of greater than about 9 pounds per gallon (“ppg”).
Well stimulations, such as fracturing operations, commonly employ viscosified treatment fluids. Fracturing operations generally involve pumping a viscous fracturing fluid into a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks or “fractures” in the subterranean formation. The fracturing fluid generally has a viscosity sufficient to carry proppant particulates to at least one fracture, inter alia, to aid in maintaining the integrity of those fractures once the hydraulic pressure is released. Once the at least one fracture is created or enhanced and the proppant particulates are substantially in place, the viscosity of the fracturing fluid may be reduced, and the fluid recovered from the formation. Fracturing operations may be performed in a wide variety of wells, including production wells completed in oil and/or gas containing formations and in injection wells used in secondary or tertiary recovery operations.
Another well stimulation treatment that employs a viscosified treatment fluid is a frac pack operation. In a frac pack operation, a fracturing operation is combined with a gravel packing operation to provide stimulated production, and an annular gravel pack to prevent and/or reduce sand production. Gravel packing is a method of controlling formation particulates (e.g., sand) in an unconsolidated section of a subterranean formation. Unconsolidated sections of subterranean formations include those that contain loose formation particulates and those wherein the bonded formation particulates have insufficient bond strength to withstand the forces produced by the production of fluids therethrough. Generally, gravel packing involves placing a filtration bed containing gravel near the well bore in order to present a physical barrier to the transport of unconsolidated formation particulates with the production of hydrocarbons. The filtration bed may be placed by the pumping and placement of the gravel into an area adjacent to a well bore in an unconsolidated section of a subterranean formation.
The downhole pressure needed to create or enhance one or more fractures in the subterranean formation is a function of the hydrostatic pressure (e.g., the weight of the hydrostatic column) and the surface pressure, provided by the pumping equipment, less the frictional pressure losses due, in part, to the tubing and other downhole equipment as the fracturing fluid passes therethrough. Today, deeper wells are being drilled and completed. For instance, wells as deep as 30,000 feet or greater have been drilled and completed. Generally, as a well is drilled deeper into a subterranean formation, a higher downhole pressure is required to fracture the formation, which, in turn, when using conventional fracturing fluids requires there to be a greater surface pressure for the needed downhole pressures to be achieved. Furthermore, dependent upon characteristics of the well, there may be greater frictional pressure losses in certain wells, which also may require there to be a greater surface pressure, when using conventional fracturing fluids, for the needed downhole pressures to be achieved. For example, surface pressures as high as 20,000 pounds per square inch (“psi”) and greater may be required when using existing treatment fluids as the deeper wells are drilled and completed. The surface pressure, however, may be limited by the pressure ratings of the surface equipment, such as the pumps, manifolds, treatment lines, wellheads, blowout preventers, and the like. For onshore operations, pumps and other surface equipment generally have a limitation of up to approximately 20,000 psi. In part, due to space limitations and the availability of flexible treatment lines with the needed increased pressure ratings, offshore operations currently may be limited to surface pressures of up to approximately 15,000 psi. In addition, to the availability of surface equipment with increased pressure ratings, another drawback to increasing surface pressure is that equipment with increased pressure ratings may add undesirable expenses to a fracturing or frac packing operation.
Another way to achieve the higher downhole pressures required for fracturing a subterranean formation in the deeper wells is to use a more dense treatment fluid than is typically used in fracturing and/or frac pack operations so that a higher hydrostatic pressure may be achieved. Furthermore, an increase in hydrostatic pressure may achieve the needed downhole pressure without an undesirable increase in surface pressures. Conventional viscosified treatment fluids used in these operations may be formulated using low concentration salt brines having a density of less than about 9 ppg. To achieve the desired viscosity of the viscosified treatment fluid, inter alia, for proppant particulate transport and to reduce leak off into the formation, the viscosified treatment fluid further may contain a viscosifying agent, such as water-soluble polymers (e.g., guar gums, cellulose derivatives, biopolymers, and the like). Viscosified treatment fluids that comprise single salt aqueous fluids with a greater density than typically used in fracturing and/or frac packing operation have been used heretofore to provide fluid loss control in subterranean operations. These fluids typically comprise a single salt aqueous fluid having a density of greater than about 9 ppg, a non-crosslinked viscosifying agent, and other conventional components. Alternatively, the viscosifying agent may be crosslinked. However, these viscosified treatment fluids that comprise a single salt aqueous fluid having a density of greater than about 9 ppg have not been used heretofore in fracturing and/or frac packing operations.